Systems and methods for producing viscous hydrocarbons

ABSTRACT

An embodiment of a method for recovering viscous hydrocarbons from a reservoir in a subterranean formation, the method including (a) continuously injecting steam into the formation, (b) injecting a first amount of a solvent into the formation for a first period of time during (a), and (c) stopping the injection of the solvent during (a) and after (b). In addition, the method includes (d) determining the effectiveness of the solvent injected during (b), and (e) injecting a second amount of the solvent into the formation during a second period of time during (a). The second amount is chosen based on the determination in (d). Further, the method includes (f) reducing a viscosity of the hydrocarbons within the reservoir with the solvent during (b) and (e).

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims priority, under 35 U.S.C. §119(e), of Provisional Application No. 61/927,419, filed Jan. 14, 2014, incorporated herein by this reference.

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

Not applicable.

BACKGROUND

The present disclosure relates generally to thermal recovery techniques for producing viscous hydrocarbons such as heavy oil and bitumen. More particularly, the present disclosure relates to systems and methods for co-injecting solvent(s) into a subterranean reservoir in connection with thermal recovery techniques to enhance production from the reservoir.

As existing reserves of conventional light liquid hydrocarbons (e.g., light crude oil) are depleted and prices for hydrocarbon products continue to rise, there is a push to find new sources of hydrocarbons. Viscous hydrocarbons, such as heavy oil and bitumen, offer an alternative source of hydrocarbons with extensive deposits throughout the world. In general, hydrocarbons having API gravity of less than 22° are referred to as “heavy oil” and hydrocarbons having an API gravity less than 10° are referred to as “bitumen.” Although recovery of heavy oil and bitumen presents challenges due to their relatively high viscosities, there are a variety of processes that can be employed to recover such viscous hydrocarbons from underground deposits.

Many techniques for recovering heavy oil and bitumen utilize thermal energy to heat the hydrocarbons, thereby decreasing the viscosity and mobilizing the hydrocarbons within the formation. The mobilization in turn enables the extraction and recovery of the hydrocarbons. Accordingly, these production and recovery processes may generally be described as “thermal” techniques. A steam-assisted gravity drainage (SAGD) operation is one thermal technique for recovering viscous hydrocarbons such as bitumen and heavy oil.

SAGD operations typically employ two vertically spaced horizontal wells drilled into the reservoir and located close to the bottom of the reservoir. Steam is injected into the reservoir through an upper, horizontal injection well, referred to as the injection well, to form a “steam chamber” that extends into the reservoir around and above the horizontal injection well. Thermal energy from the steam reduces the viscosity of the viscous hydrocarbons in the reservoir, thereby enhancing the mobility thereof and enabling them to flow downward through the formation under the force of gravity. The mobile hydrocarbons drain into the lower horizontal well, also referred to as the production well. The hydrocarbons are collected in the production well and are produced to the surface through artificial lift techniques (e.g., a pump). While SAGD and similar thermal recovery techniques have been employed with varying levels of success, production of some deposits in today's market conditions still remains economically unfeasible.

BRIEF SUMMARY OF THE DISCLOSURE

Some embodiments of the current disclosure are directed to a method for recovering viscous hydrocarbons from a reservoir in a subterranean formation. In an embodiment, the method comprises (a) continuously injecting steam into the formation, (b) injecting a first amount of a solvent into the formation for a first period of time during (a), and (c) stopping the injection of the solvent during (a) and after (b). In addition, the method comprises (d) determining the effectiveness of the solvent injected during (b), and (e) injecting a second amount of the solvent into the formation during a second period of time during (a). The second amount is chosen based on the determination in (d). Further, the method comprises (f) reducing a viscosity of the hydrocarbons within the reservoir with the solvent during (b) and (e).

Other embodiments are directed to a method for recovering viscous hydrocarbons from a reservoir in a subterranean formation. In an embodiment, the method comprises (a) continuously injecting steam into the formation through an injection well, (b) maintaining the injection of steam in (a) within +/−25% of a desired injection rate, and (c) producing the hydrocarbons to the surface through a production well extending within the formation. In addition, the method comprises (d) injecting a first amount of a solvent into the formation for a first period of time during (a), and (e) stopping the injection of the solvent during (a) and after (d). Further, the method comprises (f) injecting a second amount of the solvent into the formation during a second period of time during (a) and after (e). Still further, the method comprises (g) reducing a viscosity of the hydrocarbons within the reservoir with the solvent during (d) and (f).

Still other embodiments are directed to a method for recovering viscous hydrocarbons from a reservoir in a subterranean formation. In an embodiment, the method comprises (a) continuously injecting steam into the formation, (b) injecting a first amount of a solvent into the formation for a first period of time during (a), and (c) stopping the injection of the solvent during (a) and after (b). In addition, the method comprises (d) measuring a rate of production of the hydrocarbons from the reservoir to the surface after (b). Further, the method comprises (e) injecting a second amount of the solvent into the formation during a second period of time during (a). The second amount is chosen based on the rate of production monitored in (d). Still further, the method comprises (f) reducing a viscosity of the hydrocarbons within the reservoir with the solvent during (b) and (e).

Embodiments described herein comprise a combination of features and advantages intended to address various shortcomings associated with certain prior devices, systems, and methods. The foregoing has outlined rather broadly the features and technical advantages of the invention in order that the detailed description of the invention that follows may be better understood. The various characteristics described above, as well as other features, will be readily apparent to those skilled in the art upon reading the following detailed description, and by referring to the accompanying drawings. It should be appreciated by those skilled in the art that the conception and the specific embodiments disclosed may be readily utilized as a basis for modifying or designing other structures for carrying out the same purposes of the invention. It should also be realized by those skilled in the art that such equivalent constructions do not depart from the spirit and scope of the invention as set forth in the appended claims.

BRIEF DESCRIPTION OF THE DRAWINGS

For a detailed description of the preferred embodiments of the invention, reference will now be made to the accompanying drawings in which:

FIG. 1 is a schematic, cross-sectional side view of an embodiment of a system for producing viscous hydrocarbons from a subterranean formation in accordance with the principles disclosed herein;

FIG. 2 is a schematic, cross-sectional end view of the system of FIG. 1, taken along section II-II;

FIG. 3 is a graphical illustration of an embodiment of a method for producing viscous hydrocarbons from a reservoir in accordance with the principles disclosed herein;

FIG. 4 is a schematic graph illustrating the injection rates of both steam and solvent during exemplary production operations employing the method of FIG. 3; and

FIG. 5 is a schematic graph illustrating the injection rates of both steam and solvent during exemplary production operations employing the method of FIG. 3.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

The following discussion is directed to various exemplary embodiments. However, one skilled in the art will understand that the examples disclosed herein have broad application, and that the discussion of any embodiment is meant only to be exemplary of that embodiment, and not intended to suggest that the scope of the disclosure, including the claims, is limited to that embodiment.

Certain terms are used throughout the following description and claims to refer to particular features or components. As one skilled in the art will appreciate, different persons may refer to the same feature or component by different names. This document does not intend to distinguish between components or features that differ in name but not function. The drawing figures are not necessarily to scale. Certain features and components herein may be shown exaggerated in scale or in somewhat schematic form and some details of conventional elements may not be shown in interest of clarity and conciseness.

In the following discussion and in the claims, the terms “including” and “comprising” are used in an open-ended fashion, and thus should be interpreted to mean “including, but not limited to . . . .” Also, the term “couple” or “couples” is intended to mean either an indirect or direct connection. Thus, if a first device couples to a second device, that connection may be through a direct connection, or through an indirect connection via other devices, components, and connections. In addition, as used herein, the terms “axial” and “axially” generally mean along or parallel to a central axis (e.g., central axis of a body or a port), while the terms “radial” and “radially” generally mean perpendicular to the central axis. For instance, an axial distance refers to a distance measured along or parallel to the central axis, and a radial distance means a distance measured perpendicular to the central axis. Any reference to up or down in the description and in the claims will be made for purposes of clarity, with “up”, “upper”, “upwardly”, “uphole”, or “upstream” meaning toward the surface of the borehole and with “down”, “lower”, “downwardly”, “downhole”, or “downstream” meaning toward the terminal end of the borehole, regardless of the borehole orientation.

As previously described, SAGD operations involve the injection of steam into a reservoir to transfer thermal energy to viscous hydrocarbons contained therein in order to decrease the viscosity of and mobilize such hydrocarbons. Therefore, both the production rate and recovery efficiency of viscous hydrocarbons contained within a given reservoir are limited to the extent that the viscosity of such hydrocarbons may be reduced by the thermal energy transfer from the injected steam. As a result, in some production operations, a solvent may be injected along with steam or in lieu of steam to dilute, and thus, lower the viscosity of the hydrocarbons to a greater extent and further enhance the mobility thereof. However, the solvents themselves are costly, and thus, their use can be economically prohibitive for certain reservoirs. Thus, embodiments disclosed herein include systems and methods for optimizing the co-injection of solvent along with steam in a modified SAGD operation. Through implementation of embodiments of the systems and methods disclosed herein, an operator may enhance the recovery of viscous hydrocarbons from a reservoir while minimizing the costs required for such recovery through the optimization of both steam and solvent utilization throughout recovery operations.

Referring now to FIGS. 1 and 2, an embodiment of a system 10 for producing viscous hydrocarbons (e.g., bitumen and/or heavy oil) using a thermal recovery technique is shown. System 10 is configured to employ steam-assisted gravity drainage (SAGD) thermal recovery techniques to produce generally immobile, viscous hydrocarbons dispersed throughout a reservoir 101 in a subterranean formation 100. Reservoir 101 is vertically positioned between an overburden layer 102 and an underburden layer 103. Layers 102, 103 are formed of consolidated, generally fluid impermeable formation material (e.g., rock).

System 10 includes an injection well 20 extending from the surface 104 and a production well 30 extending from the surface 104 generally parallel to injection well 20. Each well 20, 30 extends through overburden layer 102 and includes an uphole end 20 a, 30 a, respectively, disposed at the surface 104, a downhole end 20 b, 30 b, respectively, disposed in formation 100, a generally vertical section 21, 31, respectively, extending into the formation 100 from the surface 104, and a horizontal section 22, 32, respectively, extending horizontally through reservoir 101. Horizontal sections 22, 32 are both positioned proximal the bottom or lower boundary of reservoir 101 and above underburden layer 103, with section 32 of production well 30 located below section 22 of injection well 20. In addition, horizontal sections 22, 32 are lined with perforation and/or slots lines, and thus, are both open to reservoir 101.

Referring specifically now to FIG. 1, in this embodiment, system 10 also includes an observation well 40 extending from surface 104 into the formation 100. Well 40 includes an uphole end 40 a disposed at the surface 104 and a downhole end 40 b disposed within the formation 100. In this embodiment, downhole end 40 b is disposed proximate the bottom or lower boundary of reservoir 101 and above the underburden layer 103. As will be described in more detail below, during production operations, temperature sensing devices (not shown) are arranged along well 40 to measure or monitor the temperature of the formation 100 at various depths. In general, the temperature sensing devices can be any suitable device known in the art for sensing or measuring the temperature of surrounding rock or sediment formations while still complying with the principles disclosed herein. For example, in some embodiments, the temperature sensing elements comprise thermocouples, fiber optic sensors, or some combination thereof that are installed within a tubing string that is routed through well 40. In addition, in this embodiment, horizontal section 32 of production well 30 is also outfitted with a plurality of temperature sensing devices in the same or similar manner to that described above for well 40. Without being limited to this or any other theory, during production operations, when the observed temperatures along horizontal section 32 of well 30 decline, it provides an indication that the production rates of the viscous hydrocarbons through well 30 will also begin to decline. Further, in at least some embodiments, during production operations, the temperature sensing devices within observation well 40 are used to monitor the growth of the steam chamber above and proximate sections 22, 32 of wells 20, 30, respectively, within reservoir 101. While only one observation well 40 is shown in FIG. 1, in general, any desired number of observation wells 40 can be provided to give a more accurate indication of the location of the steam chamber within the formation 100 (and particularly of the reservoir 101).

Referring now to FIG. 3, an embodiment of a method 300 for producing viscous hydrocarbons (e.g., heavy oil and/or bitumen) from reservoir 101 (or a portion of reservoir 101) using system 10 is shown. In at least some embodiments, the production of hydrocarbons is carried out through a modified SAGD thermal technique in which steam is injected into the reservoir 101 through injection well 30 along with intermittent batch slugs of a solvent based on specific parameters. As will be described in more detail below, the co-injection of solvent and steam according to method 300 offers the potential for an optimized, more economical use of solvent, as well as a more efficient recovery of the viscous hydrocarbons, thereby making the production of such heavy oil deposits more economically feasible.

In describing method 300, reference will be made to system 10 shown in FIGS. 1 and 2 in an effort to provide clarity. In addition, reference will be made to FIGS. 4 and 5 wherein schematic injection rate graphs or charts 400, 500, for producing a given reservoir (e.g., reservoir 101) are shown. For each of the charts 400 and 500, the vertical or Y-axis 402, 502, respectively, represents the injection or flow rate of material (e.g., steam and/or solvent) into the reservoir 101 through injection well 20 (e.g., cfm, gal/min, lbs/hr, etc.), and the horizontal or X-axis 404, 504, respectively, represents time (e.g., hours, days, weeks, months, years, etc.).

As used herein, the term “solvent” refers to any chemical, compound, substance, or mixture thereof that operates to dilute the viscous hydrocarbons to reduce the overall viscosity and increase the mobility thereof within a reservoir (e.g., reservoir 101). Examples of solvents include, without limitation, relatively light hydrocarbons (e.g., propane, butane, and hexane), and petroleum fractions containing a mixture of hydrocarbons (e.g., a “diluent” commonly used in bitumen separation and transportation facilities). As will be described in more detail below, during operations a solvent is injected into the formation 100 and dispersed in the hydrocarbons disposed therein. As the solvent disperses in and/or mixes with the viscous hydrocarbons, the heavy oil and/or bitumen deposits are diluted as explained above such that the overall viscosity of the hydrocarbons is reduced. The reduced viscosity increases the mobility of the hydrocarbons such that they may more easily drain toward the production well 30.

Referring still to FIG. 3, in block 305, the method 300 includes injecting steam into the reservoir 101 through the horizontal portion 22 of injection well 20. As is shown in FIGS. 4 and 5, in these embodiments, the injection of steam is maintained at a desired injection rate R_(s) (e.g., mass flow rate or volumetric flow rate of cold-water equivalent) through the entirety of operations (e.g., throughout method 300). However, in general, the injection of steam is preferably maintained at the desired injection rate R_(s) plus or minus fifty percent (+/−50%), more preferably maintained at the desired injection rate R_(s) plus or minus twenty percent (+/−25%), and even more preferably maintained at the desired injection rate R_(s) plus or minus ten percent (+/−10%).

The constant injection of steam at a fairly constant rate (e.g., injection rate R_(s)) allows the temperature of the reservoir 101 to be raised and maintained above a certain desired level throughout the execution of method 300. Without being limited to this or any other theory, the viscosity of hydrocarbons is inversely related to temperature such that as the temperature of the hydrocarbons disposed within the reservoir 101 increases, the viscosity generally decreases. Thus, in at least some embodiments, the desired steam injection rate R_(s) in block 305 is chosen to achieve and maintain a temperature in reservoir 101 associated with a desired viscosity of the hydrocarbons disposed therein in order to facilitate drainage of the hydrocarbons toward the production well 30 as previously described.

Referring again to FIG. 3, in block 310 an initial amount of solvent is co-injected along with steam into the reservoir 101 through the horizontal portion 22 of injection well 20. In this embodiment, the injection of solvent in block 310 is initiated sometime after the initiation of steam injection in block 305 (i.e., there is a time lapse between the initiation of steam injection in block 305 and the initiation of solvent injection in block 310). However, it should be appreciated that in other embodiments, the initial injection of solvent in block 310 begins at the same time that steam injection begins in block 305. In some embodiments, the initial amount of solvent injected in block 310 is chosen based on known characteristics of formation 100 and/or reservoir 101, such as, for example, the average viscosity of the hydrocarbons disposed within reservoir 101, the type of rock within reservoir 101 and/or formation 100, the average temperature of reservoir 101 and/or formation 100 as monitored by the temperature sensing devices in well 40 and/or section 32 of well 30, the height of the reservoir 101, the distance between horizontal well pairs (e.g., the distance between each pair of wells 20, 30), etc. In addition, in some embodiments, the injection rate (mass or volumetric flow rate) of solvent may be expressed as a percentage or ratio of the steam injection rate (e.g., R_(s)). For example, a given injection rate of solvent may be described in terms of a solvent-to-steam ratio which is the injection rate of solvent divided by the injection rate of steam. In some embodiments, the solvent-to-steam ratio associated with an initial solvent injection in block 310 may be approximately 0.2, such that the rate of solvent injection is twenty percent (20%) of the current injection rate of steam. However, it should be appreciated that in other embodiments, the initial injection rate of solvent in block 310 ranges from 5 to 30% of the flow rate of steam (e.g., volumetric flow rate in cold water equivalent) while still complying with the principles disclosed herein. Further, in at least some embodiments, the solvent injected in block 310 is heated such that it is in a vapor phase when it enters reservoir 101 through injection well 20.

Once the desired amount of solvent is injected into reservoir 101 in block 310, method 300 next directs the injection of solvent to be ceased in block 315. Thereafter, the effectiveness of the injection in block 310 is evaluated through, for example, the processes described in blocks 320, 325, and 330. In particular, in this embodiment, block 320 includes monitoring the rate of hydrocarbon production through the production well 30 after and/or during the injection of solvent in block 310. The rate of hydrocarbon production to the surface 104 through production well 30 provides an important insight into the effectiveness of the solvent injection in block 310 since a low or declining rate of hydrocarbon production following and/or during solvent injection in block 310 could indicate either an inadequate amount of solvent injection and/or a need to once again resume a subsequent batch of solvent injection. As a result, in some embodiments, a low rate of production in block 320 indicates that a higher amount of solvent may be necessary to bring production rates up to a desired amount. The determination as to whether the rate of hydrocarbon production from reservoir 101 is sufficiently high or low in block 320 is greatly influenced by the economic parameters and conditions associated with the particular reservoir 101. For example, a particular rate of hydrocarbon production may be considered either low or sufficient due to the particular costs associated with continued operation of a given production system (e.g., system 10) in a given reservoir 101.

In addition, block 325 includes monitoring the temperature of the formation 100 (or reservoir 101). In this embodiment, the temperature is monitored by the temperature sensing devices associated with observation well 40 (or observation wells 40) and/or horizontal section 32 of production well 30, previously described. As previously described, the temperature of the formation 100 (or reservoir 101) is of particular importance since the viscosity of the viscous hydrocarbons disposed therein is inversely related to the temperature. Thus, in block 330, the temperature of the formation 100 as monitored in block 325 is used to determine or estimate the average viscosity of the hydrocarbons contained therein. Such a determination is made based on known relationships between temperature and the viscosity for given hydrocarbon compositions. If the temperature monitored in block 325 is outside of a predetermined of expected range of values, it can serve as an indication that the amount of steam or solvent injected in blocks 305 or 310, respectively, may require adjustment. As will be described in more detail below, in some embodiments, the rate of viscous hydrocarbon production as monitored in block 320 is considered in combination with the reservoir temperature monitored in block 325 to determine the appropriate adjustment(s) to the steam and/or solvent injection amounts for continued production operations.

Once the monitored values and determinations in blocks 320, 325, 330 are made, the overall effectiveness of the solvent injection in block 310 is determined in block 335 by taking into the account the monitored production rate in block 320 and the determined viscosity of the hydrocarbons in block 325. In this embodiment, this determination is then used to adjust the amount of solvent for subsequent injections in block 340 to ensure optimized production from reservoir 101. In particular, following the determination in block 335, the method 300 adjusts the desired amount of solvent to be injected within reservoir 101 in block 340 based on the determined effectiveness in block 335 to ensure an optimum amount of solvent is injected throughout production operations. Thereafter, method 300 directs solvent to once again be co-injected with steam in block 310, with the total amount of solvent being determined through the adjustment made in block 340. Thus, the amount of solvent used in this subsequent injection of solvent in block 310 is tailored to the specific operating conditions of the reservoir 101, and the amount of solvent injected in block 310 is therefore optimized. Thereafter, the method 300 repeats blocks 320, 325, 330, 335, 340 in the same manner as previously described until production from reservoir 101 ceases such that each subsequent injection of solvent in block 310 is optimized based on feedback received from the performance of the reservoir 101 (e.g., as described in blocks 320, 325, 330). Therefore, through execution of method 300, a reservoir (e.g., reservoir 101) may be produced through the co-injection of steam and solvent such that the amount of solvent and steam injected into the reservoir can be optimized, thereby minimizing the costs of production.

Referring still to FIG. 3, in this embodiment, the monitored values and determinations in blocks 320, 325, 330 are also used to determine the timing of subsequent injection(s) of solvent into reservoir 101 in block 310. In particular, in some embodiments, block 345 includes determining when the next injection of solvent in block 310 should take place in a subsequent occurrence of block 310 based, at least partially, on the values that are monitored and/or determined in blocks 320, 325, 330. Thus, in this embodiment, as the hydrocarbon production rate monitored in block 320 decreases below a predetermined or desired range and/or as the monitored temperature of the reservoir 101 in block 325 decreases below a predetermined or desired range, a determination is made in block 345 that it is now time to reinitiate injection of solvent into the reservoir 101 in block 310 to ensure continued production of hydrocarbons from reservoir 101 at a sufficient rate. It should be appreciated that in some embodiments, both the amount (e.g., block 340) and timing (e.g., block 345) of subsequent solvent injections in block 310 are determined or influenced by the values that are monitored/determined in blocks 320, 325, 330, while in other embodiments, only one of the amount (e.g., block 340) or the timing (e.g., block 345) of subsequent solvent injections in block 310 are determined by the values that are monitored/determined in blocks 320, 325, 330, all while still complying within the principles disclosed herein.

Referring specifically now to FIGS. 4 and 5, in some embodiments, during execution of method 300, the overall amount of solvent injected into reservoir 101 for each successive injection in block 310 is typically reduced due, at least in part, to the fact that the amount of viscous hydrocarbons remaining within the reservoir 101 which the solvent can mix with is declining (e.g., because it is being produced through well 30). In addition, in at least some embodiments, each successive injection in block 310 includes a progressively smaller amount of solvent due at least in part to greater hydrocarbon mobility within the reservoir 101 as a result of progressively deeper diffusion of solvent with the such hydrocarbons. As a result, the amount of solvent used for producing a reservoir (e.g., reservoir 101) through implementation of method 300 tapers off over time.

For example, as shown in FIG. 4, in some embodiments, the amount of solvent injected with each successive solvent injection sequence may be altered by adjusting the injection rate (mass or volumetric flow rate) while keeping the elapsed time for each solvent injection substantially constant. In particular, a first solvent injection 406 is shown occurring between times T₁ and T₂ at a first injection rate R₁. Thereafter, the first solvent injection 406 is ceased at time T₂ (e.g., as described in block 315 in FIG. 3), and a second solvent injection 408 is initiated at time T₃. This second solvent injection 408 lasts until time T₄ and includes a second injection rate R₂ which is chosen based on the determined effectiveness of the first solvent injection 406 through the same analysis described above for blocks 320-340 shown in FIG. 3. In this embodiment, the elapsed time for the second solvent injection 408 (e.g., from T₃ to T₄) is the same as the elapsed time for the first solvent injection 406 (e.g., from T₁ to T₂); however, the second injection rate R₂ is lower than the first injection rate R₁ such that a smaller amount of solvent is injected during injection 408 than in injection 406. Further, the second solvent injection 408 is ceased at time T₄ (e.g., as described in block 315 in FIG. 3) and a third solvent injection 410 is initiated at time T₅. This third solvent injection 410 lasts until time T₆ and includes a third injection rate R₃ which is chosen based on the determined effectiveness of the second solvent injection 408 through the same analysis described above for blocks 320-340 shown in FIG. 3. In this embodiment, the elapsed time for the third solvent injection 410 (e.g., from T₅ to T₆) is the same as the elapsed time for the second solvent injection 406 (e.g., from T₃ to T₄) and for the first solvent injection 406 (e.g., from T₁ to T₂); however, the third injection rate R₃ is lower than the second injection rate R₂ such that a smaller amount of solvent is injected during injection 410 than in injection 408. Thus, through manipulation of the injection rate of solvent, the amount of solvent injected into the reservoir 101 with each successive solvent injection 406, 408, 410 is adjusted such that it tapers off over time. In addition, the comparison of the injection rates R₁, R₂, R₃ can also be expressed in terms of the solvent-to-steam ratio previously described. In particular, as previously described, for the system shown in FIG. 4, (R₁/R_(s)) is greater than (R₂/R_(s)) which is in turn greater than (R₃/R_(s)).

Referring now to FIG. 5, in some embodiments, the amount of solvent injected with each successive solvent injection sequence may be altered by adjusting the amount of elapsed time for each successive solvent injection while keeping the injection rate (mass or volumetric flow rate) for each solvent injection substantially constant. In particular, a first solvent injection 506 is shown occurring between times T₁ and T₂ at a solvent injection rate R_(s1). Thereafter, the solvent injection 506 is ceased at time T₂ (e.g., as described in block 315 in FIG. 3), and a second solvent injection 508 is initiated at time T₃. This second solvent injection 508 lasts until time T₄ and is carried out at the same injection rate R_(s1). However, the elapsed time for the second solvent injection 508 (e.g., between T₃ and T₄) is less than the elapsed time for the first solvent injection 506 (e.g., between T₁ and T₂) such that a smaller amount of solvent is injected for injection 508 than injection 506. This adjustment in the elapsed time for the second solvent injection 508 as compared to the elapsed time for the first solvent injection 506 is made based on a determination of the effectiveness of the first solvent injection 506 through the same analysis described above for blocks 320-340 shown in FIG. 3. The second solvent injection 508 ceases at time T₄ (e.g., as described in block 315 in FIG. 3) and a third solvent injection 510 is initiated at time T₅. This third solvent injection 510 lasts until time T₆ and is carried out at the same injection rate R_(s1) as the first solvent injection 506 and the second solvent injection 508. However, the elapsed time for the third solvent injection 510 (e.g., between T₅ and T₆) is less than the elapsed time for the second solvent injection 508 (e.g., between T₃ and T₄) such that a smaller amount of solvent is injected for injection 510 than injection 508. Thus, through manipulation of the elapsed time of solvent injection into the reservoir 101, the amount of solvent injected into the reservoir 101 with each successive solvent injection 506, 508, 510 is adjusted such that it tapers off over time.

While the method 300 described herein includes determining the effectiveness of the solvent injection in block 310 through consideration of the production rate monitored in block 320 and the determined viscosity of the hydrocarbons disposed within the reservoir 101 in block 330, in other embodiments, the effectiveness of the solvent injection in block 310 is determined through the consideration of other suitable parameters as would be known by one skilled in the art either in addition to or in lieu of the monitored and determined values of blocks 320, 325, 330. In particular, other parameters for consideration in block 335 include, for example, deviation or inefficiency in performance of the artificial lift system in the production well 30 and/or deviation or inefficiency in fluid injection behavior in injection well 20 such that the overall performance of the SAGD well-pair (e.g., wells 20 and 30) begins to decline. In addition, in some embodiments, the effectiveness of the solvent injection in block 310 as determined in block 335 is based solely through the monitored rate of hydrocarbon production in block 320, and in still other embodiments, the effectiveness of the solvent injection in block 310 as determined in block 335 is based solely on the monitored temperature of the reservoir and determined viscosity of the hydrocarbons in blocks 325, 330, respectively. Further, while the charts 400, 500 shown in FIGS. 4, 5, respectively only included three successive solvent injections 406, 408, 410, 506, 508, 510, it should be appreciated that in other embodiments, more or less than three successive solvent injections may be completed while still complying with the principles disclosed herein. Still further, while only a single injection well 20 and production well 30 are shown in FIGS. 1 and 2, it should be appreciated that in other embodiments, more than one injection wells 20 and/or production wells 30 may be included within system 10 while still complying with the principles disclosed herein.

While preferred embodiments have been shown and described, modifications thereof can be made by one skilled in the art without departing from the scope or teachings herein. The embodiments described herein are exemplary only and are not limiting. Many variations and modifications of the systems, apparatus, and processes described herein are possible and are within the scope of the invention. For example, the relative dimensions of various parts, the materials from which the various parts are made, and other parameters can be varied. Accordingly, the scope of protection is not limited to the embodiments described herein, but is only limited by the claims that follow, the scope of which shall include all equivalents of the subject matter of the claims. Unless expressly stated otherwise, the steps in a method claim may be performed in any order. The recitation of identifiers such as (a), (b), (c) or (1), (2), (3) before steps in a method claim are not intended to and do not specify a particular order to the steps, but rather are used to simplify subsequent reference to such steps. 

What is claimed is:
 1. A method for recovering viscous hydrocarbons from a reservoir in a subterranean formation, the method comprising: (a) continuously injecting steam into the formation; (b) injecting a first amount of a solvent into the formation for a first period of time during (a); (c) stopping the injection of the solvent during (a) and after (b); (d) determining the effectiveness of the solvent injected during (b); (e) injecting a second amount of the solvent into the formation during a second period of time during (a), wherein the second amount is chosen based on the determination in (d); and (f) reducing a viscosity of the hydrocarbons within the reservoir with the solvent during (b) and (e).
 2. The method of claim 1, wherein (d) comprises: (d1) monitoring a temperature of the reservoir after (b); and (d2) estimating the viscosity of the hydrocarbons in the reservoir based on the temperature monitored in (d1).
 3. The method of claim 1, wherein (d) comprises monitoring a production rate of the hydrocarbons.
 4. The method of claim 1, wherein the first amount of solvent in (b) is greater than the second amount of solvent (e).
 5. The method of claim 4, wherein (b) further comprises injecting the solvent at a first rate of injection; wherein (e) further comprises injecting the solvent at a second rate of injection; and wherein the first rate of injection is greater than the second rate of injection.
 6. The method of claim 4, wherein (b) further comprises injecting the solvent at a first solvent-to-steam ratio; wherein (e) further comprises injecting the solvent at a second solvent-to-steam ratio; and wherein the first solvent-to-steam ratio is greater than the second solvent-to-steam ratio.
 7. The method of claim 4, wherein the first period of time in (b) is greater than the second period of time in (e).
 8. The method of claim 1, wherein (a) further comprises maintaining an injection rate of steam within +/−25% of a desired injection rate.
 9. The method of claim 1, wherein both (b) and (e) comprise injecting the solvent in a vapor phase.
 10. The method of claim 1, wherein the solvent comprises hydrocarbons that have a viscosity that is less than the viscosity of the hydrocarbons within the reservoir.
 11. The method of claim 1, further comprising: (g) stopping the injection of the solvent during (a) and after (e); (h) determining the effectiveness of the injection in (e); and (i) injecting a third amount of solvent into the formation during a third period of time during (a), wherein the third amount is chosen based on the determination in (h).
 12. A method for recovering viscous hydrocarbons from a reservoir in a subterranean formation, the method comprising: (a) continuously injecting steam into the formation through an injection well; (b) maintaining the injection of steam in (a) within +1-25% of a desired injection rate; (c) producing the hydrocarbons to the surface through a production well extending within the formation; (d) injecting a first amount of a solvent into the formation for a first period of time during (a); (e) stopping the injection of the solvent during (a) and after (d); (f) injecting a second amount of the solvent into the formation during a second period of time during (a) and after (e); and (g) reducing a viscosity of the hydrocarbons within the reservoir with the solvent during (d) and (f).
 13. The method of claim 12, wherein the first amount of the solvent in (d) is greater than the second amount of the solvent (f).
 14. The method of claim 13, wherein (d) further comprises injecting the solvent at a first rate of injection; wherein (f) further comprises injecting the solvent at a second rate of injection; and wherein the first rate of injection is greater than the second rate of injection.
 15. The method of claim 13, wherein (d) further comprises injecting the solvent at a first solvent-to-steam ratio; wherein (f) further comprises injecting the solvent at a second solvent-to-steam ratio; and wherein the first solvent-to-steam ratio is greater than the second solvent-to-steam ratio.
 16. The method of claim 13, wherein the first period of time in (d) is greater than the second period of time in (f).
 17. The method of claim 12, wherein the solvent comprises a hydrocarbon that has a viscosity that is less than the viscosity of the hydrocarbons within the reservoir.
 18. The method of claim 12, further comprising: (h) stopping the injection of the solvent during (a) and after (f); and (i) injecting a third amount of solvent into the formation during a third period of time during (a).
 19. The method of claim 12, wherein both (d) and (f) comprise injecting the solvent in a vapor phase.
 20. A method for recovering viscous hydrocarbons from a reservoir in a subterranean formation, the method comprising: (a) continuously injecting steam into the formation; (b) injecting a first amount of a solvent into the formation for a first period of time during (a); (c) stopping the injection of the solvent during (a) and after (b); (d) monitoring a rate of production of the hydrocarbons from the reservoir to the surface after (b); (e) injecting a second amount of the solvent into the formation during a second period of time during (a), wherein the second amount is chosen based on the rate of production monitored in (d); and (f) reducing a viscosity of the hydrocarbons within the reservoir with the solvent during (b) and (e). 